Thunder Energy Trust

Thunder Energy Trust

March 14, 2005 09:20 ET

Thunder Energy Inc. Considering Restructuring Alternatives, Reports 2004 Financial and Operating Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: THUNDER ENERGY INC.

TSX SYMBOL: THY

MARCH 14, 2005 - 09:20 ET

Thunder Energy Inc. Considering Restructuring
Alternatives, Reports 2004 Financial and Operating
Results

CALGARY, ALBERTA--(CCNMatthews - March 14, 2005) -

Not for distribution to U.S. newswire services or for dissemination in
the
United States. Any failure to comply with this restriction may
constitute a
violation of U.S. securities law.

Thunder Energy Inc. (TSX:THY) today released restructuring alternatives
and financial and operating results for the fourth quarter and full-year
2004.

RESTRUCTURING

Thunder Energy Inc. advises that as a result of management's regular
review of options available to Thunder to increase shareholder value,
its board of directors has authorized management of Thunder to undertake
examination of possible corporate restructuring alternatives available
to Thunder to increase shareholder value. No decision on any particular
alternative has been reached at this time and there can be no assurance
that the board of directors will determine to undertake any transaction
identified and presented to it by management. Thunder has engaged
FirstEnergy Capital Corp. and GMP Securities Ltd. as co-advisers in this
regard.

Management of Thunder has been asked to consider strategic options
available to Thunder, including but not limited to: maintaining the
status quo and continuing Thunder's strategic direction as an
independent oil and natural gas exploration and development company, or
reorganizing Thunder into three parts; an energy trust, a newly formed
public exploration company and a newly formed public coal bed methane
company. With regard to the trustable assets, consideration will be
given to forming a self trust, selling those particular assets to an
existing trust and merging with other companies to form a new trust
organization.

Any restructuring initiatives identified by management will be subject
to review by, and approval of, the board of directors, and will also be
subject to the receipt of all required shareholder and regulatory
approvals.

S&P/TSX COMPOSITE INDEX

Thunder Energy Inc. has been advised by Standard & Poor's Canadian Index
Operations that the Company has been added to the Index under the Small
Cap Energy sector effective after close of business on Friday, March 18,
2005.

FINANCIAL

Cash flow for full-year 2004 was up 13 percent over 2003 to $64.0
million based on a three percent rise in the average gas price to
$6.49/mcf and 24 percent growth in the average oil and NGLs price to
$40.86/bbl. For the fourth quarter, cashflow increased 11 percent over
2003's last quarter to $15.1 million reflecting a 20 percent increase in
Thunder's average gas price, and a 46 percent jump in the average price
for oil and NGLs.

In both periods, declines were experienced in cash flow on a diluted per
share basis, reflecting the timing of production expected from major
undeveloped and non-producing assets acquired from Impact Energy Inc. in
May. Thunder's aggressive winter drilling program in northeast B.C. and
resumption of production of Whiskey Creek in 2005 will show significant
improvements in per share numbers.

Full-year net income declined 33 percent from 2003 to $15.9 million
($0.35 per share diluted). Net income for the fourth quarter decreased
42 percent from the equivalent period in 2003 to $1.2 million ($0.02 per
share diluted). The declines were primarily related to higher depletion,
depreciation and accretion expense, stock-based compensation expense and
changes in tax rates from prior periods.

PRODUCTION

For the full year, production increased seven percent from 2003 to 7,790
boe/d. Natural gas volumes were up 12 percent from 2003 to average 38.9
mmcf/d and oil and NGLs production averaged 1,309 bbls/d. For fourth
quarter 2004, production declined four percent from the same period in
2003 to 7,778 boe/d. Natural gas volumes decreased two percent to 38.8
mmcf/d, while oil and NGLs production declined 14 percent to 1,307
bbls/d reflecting Thunder's emphasis on natural gas drilling.

PROPERTY REVIEW

Northeast British Columbia

Northeast B.C. was acquired in 2004 and has become Thunder's core growth
area. Drilling is concentrated in two main areas: Laprise and Trutch.

Laprise

- Thunder drilled 16 wells (9.0 net) in the 2004/05 winter program
resulting in six natural gas wells (4.0 net), five potential gas wells
(2.9 net) and one oil well (0.6 net).

- Current gas production is 6 mmcf/d with first quarter well tie-ins
expected to increase volumes to an approximate 8 mmcf/d.

Trutch

Trutch was acquired in 2004. Offsetting Thunder's acreage is the Tommy
Lakes Halfway pool, which is estimated to contain approximately 350 bcf
and appears to trend onto Thunder's lands.

- Five wells were drilled in winter 2005 resulting in two gas wells (1.1
net), one suspended well (0.6 net) and results from two wells (1.1 net)
are under evaluation.

- Productive capacity of 5 mmcf/d (2.8 mmcf/d net) has been established
with production expected to commence next winter.

Alberta Foothills - Whiskey Creek

Thunder's operations at Whiskey Creek include a 65 percent interest in a
major gas discovery with 35 bcf (1.5 mboe) booked to date which has been
shut-in due to facility restrictions since May 2004.

- Processing capacity is expected to become available in July 2005.
Productive capability will be approximately 1,000 boe/d with completion
and tie-in of a third well by then.

- Plans call for an existing well to be whip-stocked to add further
productive capability.

Central Alberta - Shallow Gas

Central Alberta provides a stable production base from four shallow gas
areas, all with low- to medium-risk targets where Thunder has
consistently drilled with over 80% success.

- In 2004 Thunder drilled 56 wells (53.6 net), resulting in 46 gas wells
(43.6 net) and two oil wells (2.0 net).

- Central Alberta shallow gas production in 2004 averaged 34.4 mmcf/d
with oil and NGLs production of 1,215 bbls/d.

Coal Bed Methane (CBM)

Thunder commercialized one CBM project in 2004, and expects to move
towards commercialization of three additional CBM projects in late 2005
or into 2006.

- Thunder is attempting to prove up as much as 1.3 tcf of identified CBM
gas resources.

- In 2004 Thunder drilled 47 CBM wells (46.6 net).

- Production from Thunder's commercial CBM project, located at Fenn-Big
Valley, is an approximate 2.5 mmcf/d with a rise to 3.5 mmcf/d expected
in first half 2005.

- At Rosalind, in the Manville coal trend, Thunder has two pilot
projects currently being evaluated and plans to drill two horizontal
wells in Q2/2005. These projects are a joint venture with Burlington
Resources.

- Thunder's 100% owned CBM pilot project at Manola offsets Corbett
Creek, one of the industry's major CBM pilot projects which is reported
to be nearing commercialization. Thunder's project is investigating
production capability from the same Mannville coal trend which, to date,
has yielded some wells with relatively prolific production rates,
including horizontal wells producing at rates in the 200-300 mcf/d range.

High-impact Exploration

Thunder is investing a moderate amount of capital to drilling 2-4
high-impact exploration wells each year. In 2004, Thunder spent $2.9
million to drill two of these wells.

- The target zone for a well at Stolberg in the Alberta Foothills failed
to encounter commercial quantities of hydrocarbons. A second zone is
being evaluated.

- Results of a second high-impact well, located at Sojer in northeast
B.C. are under evaluation.

- In 2005, Thunder plans to spend approximately $4.5 million on three
exploration wells encompassing high-potential plays in the Alberta
Foothills and northeast B.C.

RESERVES

The reserve results are from Thunder's independent year-end reserve
evaluation prepared by Gilbert Laustsen Jung and Associates Ltd. ("GLJ")
effective December 31, 2004 which evaluated 100 percent of the Company's
reserves. For year-end December 31, 2003, Thunder's reserves were
evaluated 100 percent by Sproule Associates Limited ("Sproule"). The
report was prepared utilizing the reserve definitions as prescribed by
National Instrument 51-101. A full detailed report will be provided in
our Annual Information Form to be filed on SEDAR on or before March 31,
2005.

Total gas reserves (proved plus probable or P+P) increased 32 percent to
184 bcf over year-end 2003. Total reserves of crude oil and NGLs
decreased 10 percent to 5.9 million bbls. The value of Thunder's total
reserves, discounted at 10 percent, increased 30 percent to $394
million. Thunder has a Reserve Committee of independent board members
who evaluate, select and appoint the independent reserve evaluators. The
committee also reviews the process and technical data used to determine
the reserves booked and approved the final independent evaluation.



------------------------------------------------------------------------
December 31, December 31, Percentage
2004 2003 Change
------------------------------------------------------------------------
Proved reserves
Natural gas (bcf) 127 88 44%
Crude oil and NGLs (mbbls) 4,491 4,375 3%
Oil equivalent (mboes) 25,620 19,070 34%
Proved plus probable reserves
Natural gas (bcf) 184 139 32%
Crude oil and NGLs (mbbls) 5,910 6,558 (10%)
Oil equivalent (mboes) 36,551 29,750 23%

Undeveloped land (acres) 304,305 197,692 54%

Net present value of future cash
flow before tax at 10% before tax
($ millions)
Proved 299 221 35%
Probable 95 83 14%
Proved + Probable 394 304 30%

Reserve Life Index (years)
Proved 9.0 6.5 38%
Proved + Probable 12.9 10.1 28%
------------------------------------------------------------------------


FINDING & DEVELOPMENT COSTS

For 2004, total proved plus probable reserve additions were 9.7 million
boe. Conventional drilling operations added 4.7 million boe, CBM
operations added 1.4 million boe, the Impact acquisition added 11.9
million boe offset by 8.3 million boe in reserve revisions. The CBM
reserves relate to Thunder's shallow Horseshoe Canyon coal bed methane
program at Fenn-Big Valley.

Total capital spent in 2004 on oil and gas expenditures was $229.8
million, including $137.0 million related to the Impact acquisition,
resulting in finding and development costs (F&D) prior to reserve
revisions of $12.78/boe ($13.54/boe including future capital). During
the year, Thunder drilled a total of 117 wells (108.3 net). An
improvement in the reserve life index (RLI) to 12.9 years, P+P, has
resulted from the investment in long life reserve assets in northeast
British Columbia and the Alberta Foothills, combined with the moderation
in decline of our shallow gas reserves.

RESERVE REVISIONS

For the year ended December 31, 2004 Thunder changed reserve evaluators
to GLJ from Sproule. Included in the current report Thunder recorded
downward technical revisions of 800 thousand boe proved producing, 3.2
million boe total proved and 8.3 million boe proved plus probable.
Revisions resulted from a combination of well performance and
interpretation differences between evaluators.

FORWARD-LOOKING STATEMENTS

This press release may contain forward-looking statements including
expectations of future production, cash flow and earnings. These
statements are based on current expectations that involve a number of
risks and uncertainties, which could cause actual results to differ from
those anticipated. These risks include, but are not limited to: the
risks associated with the oil and gas industry (e.g., operational risks
in development, exploration and production; delays or changes in plans
with respect to exploration or development projects or capital
expenditures; the uncertainty of reserve estimates; the uncertainty of
estimates and projections relating to production, costs and expenses,
and health, safety and environmental risks), commodity price and
exchange rate fluctuation and uncertainties resulting from potential
delays or changes in plans with respect to exploration or development
projects or capital expenditures. Additional information on these and
other factors that could affect the Company's operations or financial
results are included in the Company's reports on file with Canadian
securities regulatory authorities.

Thunder Energy Inc. is a Calgary-based oil and gas exploration company.
Thunder's shares trade on the Toronto Stock Exchange under the trading
symbol "THY".



HIGHLIGHTS
Three
Months Ended Years Ended
Financial December 31 % December 31 %
($000s, except per
share data) 2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------

Petroleum and natural
gas sales 29,049 25,208 15 116,409 102,201 14
Cash flow from
operations 15,076 13,537 11 63,978 56,718 13
per share - basic 0.30 0.43 (30) 1.45 1.81 (20)
- diluted 0.29 0.41 (29) 1.41 1.74 (19)
Net income 1,207 2,065 (42) 15,928 23,610 (33)
per share - basic 0.02 0.07 (71) 0.36 0.75 (52)
- diluted 0.02 0.06 (67) 0.35 0.72 (51)
Capital expenditures 34,729 16,853 106 93,245 69,943 33
Debt including
working capital
deficiency and
capital lease
obligations 107,437 82,956 30 107,437 82,956 30
Average shares
outstanding - basic 50,659 31,554 61 44,214 31,414 41
------------------------------------------------------------------------

Three
Months Ended Years Ended
Operations December 31 % December 31 %
2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------

Daily production
Natural gas (mcf/d) 38,827 39,520 (2) 38,887 34,590 12
Oil and NGLs (bbls/d) 1,307 1,517 (14) 1,309 1,522 (14)
Barrels of oil
equivalent (boe/d) 7,778 8,103 (4) 7,790 7,288 7
Average sale prices
Natural gas ($/mcf) 6.57 5.47 20 6.49 6.31 3
Oil and NGLs ($/bbl) 43.24 29.68 46 40.86 32.89 24
Wells drilled
- gross (net)
Gas 22(16.8) 15(15.0) 59(51.1) 69(65.3)
Oil 1(1) 5(5.0) 2(2.0) 17(17.0)
CBM 8(8.0) 4(3.0) 47(46.6) 11(7.5)
Dry 5(4.6) 2(2.0) 9(8.6) 14(11.5)
Total 36(30.4) 26(25.0) 117(108.3) 111(101.2)
------------------------------------------------------------------------
------------------------------------------------------------------------
Barrels of oil equivalent are reported with a 6:1 conversion with six
mcf = one barrel


MANAGEMENT'S DISCUSSION AND ANALYSIS

Statements made throughout this quarterly report may contain
forward-looking statements including expectations of future production,
cash flow and earnings. These statements are based on current
expectations that involve a number of risks and uncertainties, which
could cause actual results to differ from those anticipated. These risks
include, but are not limited to: the risks associated with the oil and
gas industry (e.g. operational risks in development, exploration and
production; delays or changes in plans with respect to exploration or
development projects or capital expenditures; the uncertainty of reserve
estimates; the uncertainty of estimates and projections relating to
production, costs and expenses; health, safety and environmental risks);
and commodity price and exchange rate fluctuations. Additional
information on these and other factors that could affect Thunder Energy
Inc.'s ("Thunder" or the "Company") operations or financial results are
included in Thunder's reports on file with Canadian securities
regulatory authorities.

The following discussion and analysis as provided by the management of
Thunder should be read in conjunction with the audited consolidated
financial statements for the years ended December 31, 2004 and 2003.

Basis of presentation - The financial data presented below has been
prepared in accordance with Canadian generally accepted accounting
principles ("GAAP"). The reporting and the measurement currency is the
Canadian dollar.

BOE presentation - The term barrels of oil equivalent (boe) may be
misleading, particularly if used in isolation. The boe conversion ratio
used by the Company of 6 mcf: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead. All boe conversions in
this report are derived by converting gas to oil in the ratio of six
thousand cubic feet of gas to one barrel of oil.

Gross oil and gas revenues increased 15% to $29.0 million in fourth
quarter 2004 compared with the same period in 2003 due to stronger
commodity pricing which was offset by a 2% decrease in natural gas
production. Oil and NGLs production decreased 14% in the quarter, which
was offset by increased prices. Natural gas prices averaged 20% higher
than in 2003, while average oil and NGLs pricing jumped 46%. For the
year, revenues were up 14% over 2003 to $116.4 million, based on 12%
growth in average natural gas volumes and a 24% rise in the average
price for oil and NGLs, offset by a 14% decline in production for oils
and NGLs.

The financial statements for the period ended December 31, 2004 have
been restated to segregate costs associated with the transportation and
selling of natural gas, crude oil and NGLs. Previously, Thunder followed
the industry practice of presenting revenues net of these costs. The
table below calculates revenue and segregates transportation costs.



Oil and Gas Revenue ($000s)
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Gross revenues 29,049 25,208 116,409 102,201
Transportation expenses (997) (1,133) (4,225) (4,011)
----------------------------------------
Net revenues 28,052 24,075 112,184 98,190
----------------------------------------
----------------------------------------


Oil and Gas Revenue ($000s, net of transportation expenses)

Crude Oil
Natural Gas and NGLs Total
------------------------------------
------------------------------------
Three months ended December 31, 2003 19,933 4,142 24,075
Effect of change in product prices 3,269 1,629 4,898
Effect of change in sales volumes (349) (572) (921)
------------------------------------
Three months ended December 31, 2004 22,853 5,199 28,052
------------------------------------
------------------------------------


Crude Oil
Natural Gas and NGLs Total
------------------------------------
------------------------------------
Year ended December 31, 2003 79,910 18,280 98,190
Effect of change in product prices 2,801 3,880 6,681
Effect of change in sales volumes 9,902 (2,589) 7,313
------------------------------------
Year ended December 31, 2004 92,613 19,571 112,184
------------------------------------
------------------------------------


Production
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Crude oil (bbls/d) 1,160 1,356 1,152 1,369
NGLs (bbls/d) 147 161 157 153
----------------------------------------
Total oil and NGLs (bbls/d) 1,307 1,517 1,309 1,522
----------------------------------------
Natural gas (mcf/d) 38,827 39,520 38,887 34,590
----------------------------------------
Total boe (boe/d) 7,778 8,103 7,790 7,288
----------------------------------------
----------------------------------------


Commodity prices received by Thunder are based on the respective
reference prices for both crude oil and natural gas adjusted for
transportation and quality differentials, as applicable, and foreign
exchange. The average price for oil and NGLs in the quarter increased
46% over fourth quarter 2003. The benchmark West Texas Intermediate
("WTI") oil price averaged US$48.28/bbl in the fourth quarter of 2004, a
55% increase over fourth quarter 2003. For the year to date, Thunder's
average crude and NGLs price was up 24% from 2003. Thunder's average
natural gas price for the fourth quarter increased 20% over the same
period in 2003. For the year, the average price increased 3% from 2003.

Transportation expenses for the fourth quarter decreased 12% from 2003
to $1.0 million and 5% to $4.2 million for the year. These amounts
relate to the cost of transporting natural gas on the main natural gas
pipelines and for oil trucking charges. In the past, these amounts were
offset against revenue and not disclosed separately. Prior periods have
been restated to reflect this change in presentation.



Average Commodity Prices
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Natural gas ($/mcf)
NYMEX ($US/mcf) 7.24 5.42 6.18 5.49
AECO 6.57 5.76 6.55 6.70
Thunder price before
transportation 6.77 5.71 6.70 6.53
Transportation (0.20) (0.24) (0.21) (0.22)
----------------------------------------
Thunder price at the wellhead 6.57 5.47 6.49 6.31
----------------------------------------
----------------------------------------
Crude oil ($/bbl)
WTI ($US/bbl) 48.28 31.18 41.40 31.04
Edmonton posted 57.71 39.56 52.54 43.14
Thunder price before
transportation 45.54 31.48 43.34 35.04
Transportation (2.30) (1.80) (2.48) (2.15)
----------------------------------------
Thunder price at the wellhead 43.24 29.68 40.86 32.89
----------------------------------------
----------------------------------------

Cdn/US $ average exchange rate 1.211 1.316 1.299 1.401
----------------------------------------
----------------------------------------


Royalties decreased in both periods compared with the prior year due to
a $0.7 million gas cost allowance adjustment received in the second
quarter relating to 2003, and a $0.3 million refund as a result of a
prior period royalty dispute. The current Crown rate is decreasing as
claims for gas cost allowances are increasing.



Royalties ($000s)
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Crown 3,939 4,593 17,607 18,747
Freehold and other 880 593 3,815 3,304
----------------------------------------
Gross royalties 4,819 5,186 21,422 22,051
ARTC (125) (69) (500) (444)
----------------------------------------
Net royalties 4,694 5,117 20,922 21,607
----------------------------------------
----------------------------------------


Royalty Rates (as a % of revenue, net of transportation expenses)

Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Crown 14.0 19.1 15.7 19.1
Freehold and other 3.1 2.5 3.4 3.4
----------------------------------------
Gross royalties 17.1 21.6 19.1 22.5
ARTC (0.4) (0.3) (0.5) (0.5)
----------------------------------------
Net royalties 16.7 21.3 18.6 22.0
----------------------------------------
----------------------------------------


Operating costs increased 39% to $7.58/boe in fourth quarter 2004 from
the same period in 2003; for the year operating costs increased 24% to
$6.77/boe. These increases reflect the industry as a whole experiencing
higher costs, and the effect of the acquisition of Impact, which had
higher operating costs per boe due to the nature of its assets. The
fourth quarter operating costs would have been approximately $6.90 per
boe without the effect of reallocating under accruals from previous
quarters.



Operating Costs
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Operating costs ($000s) 5,421 4,061 19,299 14,480
Per boe ($) 7.58 5.45 6.77 5.44
----------------------------------------
----------------------------------------


Gross general and administrative expenses (G&A) increased 125% over 2003
on a per boe basis during the fourth quarter and 58% per boe for the
year-to-date due to increased staff as a result of the Impact
acquisition, one-time integration costs of $0.5 million, and other
non-recurring charges of $0.3 million. Taking the foregoing into
account, the normalized going forward rate for net G and A is
approximately $1.50 per boe.



G&A Expenses
Three months ended Years ended
December 31 December 31
G&A Expenses ($000s) 2004 2003 2004 2003
----------------------------------------
Gross G&A expenses 2,652 1,228 7,849 4,615
Overhead recoveries
Capital (398) (354) (2,323) (1,273)
Operating (307) (210) (1,262) (1,093)
----------------------------------------
Total recoveries (705) (564) (3,585) (2,366)
----------------------------------------
Net G&A expenses 1,947 664 4,264 2,249
----------------------------------------
----------------------------------------

G&A Expenses Per BOE ($)
Gross G&A expenses 3.71 1.65 2.75 1.74
Overhead recoveries
Capital (0.56) (0.48) (0.81) (0.48)
Operating (0.43) (0.28) (0.44) (0.41)
----------------------------------------
Total recoveries (0.99) (0.76) (1.25) (0.89)
----------------------------------------
Net G&A expenses 2.72 0.89 1.50 0.85
----------------------------------------
----------------------------------------


Interest expense rose 21% over fourth quarter 2003 and 13% for the year
due to higher bank debt as Thunder's capital activity level increased.



Interest Expense
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Interest expense ($000s) 725 597 3,094 2,740
Average revolving demand bank
debt outstanding ($000s) 85,463 71,450 80,020 67,166
Effective annualized interest
rate for the period (%) 3.4 3.3 3.9 4.1
----------------------------------------
----------------------------------------


Depletion, depreciation and accretion (DD&A) expenses increased $4.64
per boe over the fourth quarter of 2003 and $4.08 per boe for the
year-to-date. In the fourth quarter of 2004, the DD&A rate increased as
a result of general industry costs increasing and a 9% decrease in
proven reserves. DD&A also includes accretion expense related to the
asset retirement obligation. Prior year DD&A has been adjusted to
reflect accretion expense as the application of the accounting policy
was retroactive.



DD&A
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
DD&A ($000s) 10,984 7,985 36,200 22,935
Per boe ($) 15.35 10.71 12.70 8.62
----------------------------------------
----------------------------------------


Stock-based compensation expense decreased to $0.7 million in the fourth
quarter 2004 from the third quarter of 2004 due to 0.2 million stock
options being cancelled. The year-to-date expense increased to $2.5
million from $0.5 million in 2003. In the second quarter 2004, 2.3
million options were issued coincident with the Impact acquisition.

The provision for income taxes increased over 2004 compared to the prior
year due to an increase in non-deductible stock-based compensation and a
decrease in the effect of tax rate adjustments which more than offset
the decrease in net income before taxes. The Company's future income tax
provision and future tax liability for the year ended December 31, 2004
decreased by approximately $1.6 million as a result of changes to
Alberta tax legislation that reduced the statutory corporate income tax
rates by 1% on earned income from resource activities. As at December
31, 2004, the Company had $251 million in tax pools available to shelter
future income and does not anticipate paying current income tax in 2004
or 2005. The tax pools available are as follows:



Tax Pools ($000s)
2004
---------
---------
Canadian oil and gas property expenses (COGPE) 53,367
Canadian development expenses (CDE) 64,382
Canadian exploration expense (CEE) 67,504
Undepreciated capital costs (UCC) 59,186
Non-capital tax loss carryforwards 4,286
Share issue costs 2,330
---------
Total 251,055
---------
---------


Cash flow from operations increased 11% in fourth quarter 2004 over the
same period in 2003 reflecting higher commodity prices that were offset
by a decline in production. For the year-to-date, cash flow from
operations increased 13% due to a 7% increase in total production from
2003, a 24% increase in oil and NGL prices and 3% increase in gas prices.



Cash Flow from Operations
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Cash flow from operations ($000s) 15,076 13,537 63,978 56,718
Per share - basic ($) 0.30 0.43 1.45 1.81
- diluted ($) 0.29 0.41 1.41 1.74
----------------------------------------
----------------------------------------


Net income decreased 42% in the fourth quarter and 33% for the
year-to-date compared with the same periods of 2003 due to increased
DD&A expense, stock-based compensation expense and changes in tax rates
from previous periods.



Net Income
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Net Income ($000s) 1,207 2,065 15,928 23,610
Per share - basic ($) 0.02 0.07 0.36 0.75
- diluted ($) 0.02 0.06 0.35 0.72
----------------------------------------
----------------------------------------


Capital expenditures for the year aggregated $93.2 million. Land
acquisitions totalled $9.1 million as the Company acquired 144,000 net
acres of undeveloped land. Total seismic costs came to $6.0 million for
the shooting of 369 kilometres of 2D and 47 square kilometres of 3D
seismic, plus the purchase of 775 kilometres of 2D seismic and 30 square
kilometres of 3D seismic data. Conventional drilling, completion,
equipping and tie-in costs totalled $56.9 million for the drilling of 59
gas wells (51.1 net), two oil wells (2.0 net) and nine dry holes (8.6
net). Thunder invested $15.0 million in the drilling, completion and
equipping of 47 coal bed methane wells (46.6 net). The Company had an
overall drilling success ratio of 92%. Facilities and gas gathering
costs totalled $6.1 million and acquisition and other costs aggregated
$0.1 million.

At December 31, 2004, costs of $46,288,400 (2003 - $9,884,600) related
to unproven properties have been excluded from the full cost pool. The
rise over 2004 is due to increases in the price per acre, total acreage
and costs associated with coal bed methane pilot projects.

The table below breaks out the capital expenditures by category:



Capital Expenditures ($000s)
Three months ended Years ended
December 31 December 31
2004 2003 2004 2003
----------------------------------------
Land and rentals 1,578 1,291 9,138 6,578
Seismic 1,113 340 5,988 2,385
Conventional drilling and
completions 19,587 8,502 43,411 40,200
Well equipping and tie-in 5,571 3,179 13,483 9,991
Facilities and gas gathering 1,639 1,803 6,067 7,022
Acquisition costs, net of
dispositions (11) - (231) 155
Other 39 36 373 467
----------------------------------------
Total conventional capital
expenditures 29,516 15,151 78,229 66,798
----------------------------------------
CBM drilling, completion and
facilities 5,213 1,702 15,016 3,145
----------------------------------------
Total capital expenditures 34,729 16,853 93,245 69,943
----------------------------------------
----------------------------------------


Business Combination

On April 30, 2004, the Company acquired all of the issued and
outstanding common shares of Impact Energy Inc. ("Impact") on the basis
of 0.22222 common shares of Thunder for each common share of Impact. The
value per common share issued was calculated as the average Thunder
closing share price five days before and five days after the
announcement of the acquisition. Thunder issued 18,100,317 common shares
as consideration and incurred $1.1 million in transaction costs.
Subsequent to the date of acquisition, the preliminary allocation of the
purchase price was adjusted to reflect Thunder's current understanding
of fair values as at the date of acquisition. This transaction was
accounted for by the purchase method, based on fair values as follows:



Net assets acquired ($000s)
Current assets, including cash of $14 $ 2,692
Property and equipment 120,727
Goodwill 45,448
Current liabilities (8,912)
Asset retirement obligations (778)
Future income tax liability (22,226)
-----------
$ 136,951
-----------
-----------

Value of common shares of Thunder issued $ 135,835
Transaction costs 1,116
-----------
Total consideration $ 136,951
-----------
-----------


Liquidity

For the year ended December 31, 2004, capital expenditures of $93.2
million, abandonment costs of $0.2 million, the assumption of $6.2
million in negative working capital from Impact and Impact transaction
costs of $1.1 million were funded by cash flow from operations of $64.0
million, $12.2 million in proceeds from the issuance of share capital
resulting from the exercise of stock options and the issuance of $10.0
million in flow-through shares, and an increase of $24.5 million in net
debt including working capital from operating and investing activities.
Thunder's accounts receivable and accounts payable increased $8.1
million due to cash calls made to partners at year-end to fund the first
quarter capital program. Thunder's revolving bank debt was $82.9 million
at December 31, 2004. Although this loan is demand in nature and
accordingly is presented as a current liability, the bank has confirmed
that it is not its intention to call for repayment before December 31,
2005, provided there is no adverse change in the financial position of
the Company. Thunder's bank line is $130 million at December 31, 2004.

Asset Retirement Obligations

Thunder adopted Section 3110 of the CICA Handbook on January 1, 2004. As
a result of implementation, the liability for future abandonment costs
(the "Asset Retirement Obligation" or "ARO") was $13.4 million at
December 31, 2004. For the year ended December 31, 2004, the PP&E
balance increased by $2.1 million (three months ended December 31, 2004
- $0.6 million).

The transitional provisions of this section require that the standard be
applied retroactively with restatement of comparative periods. As a
result of the retroactive application, 2003 comparative numbers have
been restated to reflect the impact of this standard on the 2003
financial statements. In comparison to amounts previously reported as at
December 31, 2003, net income after applicable income taxes decreased by
$0.5 million, ARO increased by $10.4 million, PP&E balance increased by
$5.1 million (net of accumulated depreciation of $3.1 million), future
tax liability decreased by $1.2 million and opening 2003 retained
earnings decreased by $2.1 million net of applicable income taxes.
Opening 2004 retained earnings decreased by $2.6 million net of
applicable income taxes for the cumulative impact of retroactive
restatement of all prior years.



Quarterly Information
------------------------------
2003
($000s, except per share data) Q1 Q2 Q3 Q4
------------------------------
Petroleum and natural gas sales 29,093 22,836 25,065 25,207
Cash flow from operations 17,329 12,195 13,657 13,537
Per share ($)
Basic 0.56 0.39 0.43 0.43
Diluted 0.53 0.38 0.42 0.41
Net income 7,433 8,798 5,314 2,065
Per share ($)
Basic 0.24 0.28 0.17 0.07
Diluted 0.23 0.27 0.16 0.06
------------------------------

------------------------------
2004
($000s, except per share data) Q1 Q2 Q3 Q4
------------------------------

Petroleum and natural gas sales 28,232 30,883 28,245 29,049
Cash flow from operations 15,006 18,436 15,460 15,076
Per share ($)
Basic 0.47 0.42 0.31 0.30
Diluted 0.45 0.41 0.30 0.29
Net income 5,698 5,698 3,325 1,207
Per share ($)
Basic 0.18 0.13 0.07 0.02
Diluted 0.17 0.13 0.06 0.02
------------------------------


Non-GAAP Measurements

This Management's Discussion and Analysis contains the term cash flow
from operations, which should not be considered an alternative to, or
more meaningful than, cash flow from operating activities or net income
as determined in accordance with Canadian generally accepted accounting
principles as an indicator of the Company's performance. Thunder's
determination of cash flow from operations may not be particularly
comparable to that reported by other companies especially those in other
industries. It is presented because management believes the information
is useful for investors as it is used internally and widely accepted by
those following the oil and gas industry as a financial indicator of a
company's ability to generate cash to internally fund exploration and
development activities and service debt. This term is also used by
research analysts to value and compare oil and gas exploration and
production companies, and is frequently included in published research
when providing investment recommendations. The reconciliation between
net earnings and cash flows from operations can be found in the
consolidated statements of cash flows in the audited consolidated
financial statements. The Company also presents cash flow from
operations per share whereby per share amounts are calculated using
weighted average shares outstanding consistent with the calculation of
earnings per share.



THUNDER ENERGY INC.
CONSOLIDATED BALANCE SHEETS
($000s) December 31, December 31,
2004 2003
--------------------------
(restated
- Note 3)
Assets (Note 6)
Current
Cash $ 21 $ -
Accounts receivable (Note 9) 23,728 11,343
Prepaid expenses 953 848
--------------------------
24,702 12,191
Property and equipment (Note 5) 406,082 225,909
Goodwill (Note 4) 45,448 -
--------------------------
$ 476,232 $ 238,100
--------------------------
--------------------------


Liabilities and Shareholders' Equity
Current
Bank indebtedness $ 1,568 $ 1,923
Accounts payable and accrued liabilities 47,581 18,738
Revolving demand loan (Note 6) 82,896 74,348
--------------------------
132,045 95,009
--------------------------

Capital lease obligations 94 138
Asset retirement obligations (Note 3) 13,417 10,352
Future income taxes (Note 8) 66,934 35,652
--------------------------
212,490 141,151

Shareholders' equity
Share capital (Note 7) 189,573 41,081
Contributed surplus (Note 7) 2,836 463
Retained earnings 71,333 55,405
--------------------------
263,742 96,949
--------------------------
$ 476,232 $ 238,100
--------------------------
--------------------------
See accompanying notes


THUNDER ENERGY INC.
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS

Three Months Ended Years Ended
December 31 December 31
(unaudited)

($000s, except per share data) 2004 2003 2004 2003
---------------------------------------
(restated (restated
- Note 3) - Note 3)
Revenue
Petroleum and natural gas sales $ 29,049 $ 25,208 $116,409 $102,201
Royalties, net of ARTC (4,694) (5,117) (20,922) (21,607)
Transportation expenses (997) (1,133) (4,225) (4,011)
---------------------------------------
Petroleum and natural gas sales,
after royalties and
transportation 23,358 18,958 91,262 76,583
---------------------------------------

Expenses
Operating 5,421 4,061 19,299 14,480
General and administrative 1,947 664 4,264 2,249
Stock-based compensation
(Note 7) 700 463 2,514 463
Interest 725 597 3,094 2,740
Depletion, depreciation and
accretion 10,984 7,985 36,200 22,935
---------------------------------------
19,777 13,770 65,371 42,867
---------------------------------------

Income before taxes 3,581 5,188 25,891 33,716
Provision for income taxes
(Note 8) 2,374 3,123 9,963 10,106
---------------------------------------
Net income for the period 1,207 2,065 15,928 23,610
---------------------------------------
Retained earnings
Beginning of period 70,126 55,771 55,405 33,862
Retroactive application of
change in accounting policy
(Note 3) - (2,431) - (2,067)
---------------------------------------
End of period $ 71,333 $ 55,405 $ 71,333 $ 55,405
---------------------------------------
---------------------------------------

Shares outstanding
(weighted average)
Basic 50,659 31,554 44,214 31,414
Diluted 51,640 33,113 45,250 32,645
Net income per share
Basic $ 0.02 $ 0.07 $ 0.36 $ 0.75
Diluted $ 0.02 $ 0.06 $ 0.35 $ 0.72
---------------------------------------
---------------------------------------
See accompanying notes


THUNDER ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended Years Ended
December 31 December 31
(unaudited)

($000s) 2004 2003 2004 2003
---------------------------------------
Operating Activities (restated (restated
- Note 3) - Note 3)
Net income for the year $ 1,207 $ 2,065 $ 15,928 $ 23,610
Add items not requiring cash:
Stock-based compensation 700 463 2,514 463
Depletion, depreciation and
accretion 10,984 7,985 36,200 22,935
Future income taxes (Note 8) 2,185 3,024 9,336 9,710
--------------------------------------
Cash flow from operations 15,076 13,537 63,978 56,718
Site restoration and abandonment (49) (124) (159) (124)
Changes in non-cash working
capital related to operating
activities (5,895) 8,467 (10,391) (671)
--------------------------------------
Cash provided by operating
activities 9,132 21,880 53,428 55,923

Financing Activities
Issue of common shares for cash,
net of costs 10,366 54 12,237 1,154
Increase (decrease) in revolving
demand loan (3,260) 3,452 8,548 8,870
Increase (decrease) in bank
indebtedness (546) 1,923 (355) 1,440
--------------------------------------
Cash provided by financing
activities 6,560 5,429 20,430 11,464

Investing Activities
Expenditures on property and
equipment (34,729) (16,853) (93,245) (69,943)
Assumption of working capital
(Note 4) (805) - (6,220) -
Transaction costs on Impact
acquisition (Note 4) (67) - (1,116) -
Changes in non-cash working
capital related to investing
activities 19,930 (10,456) 26,744 2,556
--------------------------------------
--------------------------------------
Cash used in investing
activities (15,671) (27,309) (73,837) (67,387)
--------------------------------------
Net change in cash position 21 - 21 -
Cash position - beginning of year - - - -
--------------------------------------
- end of year $ 21 $ - $ 21 $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2004 and 2003

1. Nature of Operations

Thunder Energy Inc. (the "Company") was incorporated under the laws of
the Province of Alberta on October 17, 1995. On April 30, 2004, Thunder
purchased all of the outstanding shares of Impact Energy Inc.
("Impact"). The transaction was accounted for using the purchase method.
Accordingly, the consolidated financial statements include those of the
Company from inception and those of the combined companies from the date
of acquisition to December 31, 2004. All intercompany transactions and
balances have been eliminated.

The Company's primary business is the acquisition of, and the
exploration for and development and production of crude oil and natural
gas. The Company has properties in both Canada and the United States.
The Company has no proven reserves in the United States and the holdings
are not significant to the consolidated financial statements. All
activity is conducted in Western Canada and comprises a single business
unit.

2. Significant Accounting Policies

The consolidated financial statements of the Company have been prepared
in accordance with Canadian generally accepted accounting principles.
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the
date of the consolidated financial statements, and revenues and expenses
during the reporting period. Actual results could differ from those
estimated.

Specifically, the amounts recorded for depletion, depreciation and
accretion of oil and natural gas properties and equipment and asset
retirement obligations are based on estimates. The ceiling test is based
on estimates of proved reserves, production rates, oil and gas prices,
future costs and other relevant assumptions. By their nature, these
estimates are subject to measurement uncertainty and the effect on the
financial statements of changes in such estimates in future periods
could be significant.

Principles of consolidation

The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All intercompany transactions
and balances have been eliminated.

Petroleum and natural gas properties and gas plants and related
facilities

The Company follows the full cost method of accounting whereby all costs
associated with the acquisition of and the exploration for and
development of petroleum and natural gas reserves, whether productive or
unproductive, are capitalized in one Canadian cost centre and charged to
income as set out below. Such costs include lease acquisition, drilling,
equipping, geological and geophysical costs and overhead expenses
directly related to exploration and development activities. No indirect
general and administrative costs have been capitalized.

Gains or losses are not recognized upon disposition of petroleum and
natural gas properties unless crediting the proceeds against accumulated
costs would result in a change in the rate of depletion of 20% or more.

Depletion and depreciation

Depletion of petroleum and natural gas properties is provided on
accumulated costs using the unit of production method based on estimated
gross proven petroleum and natural gas reserves, as determined by
independent engineers. For purposes of the depletion calculation, proven
petroleum and natural gas reserves are converted to a common unit of
measure on the basis of one barrel of oil or liquids being equal to six
mcf of natural gas. Costs of acquiring and evaluating unproven
properties, including coal bed methane pilot projects, are excluded from
depletion calculations until it is determined whether or not proven
reserves are attributable to the properties or impairment occurs.

Depreciation of gas plants and related facilities is calculated on a
straight-line basis over their estimated useful lives of fifteen years.
Assets under capitalized lease are amortized on a straight-line basis
over the three-year life of the lease.

The Company records other assets at cost and provides depreciation on
the declining balance method at rates varying from 20% to 100% per annum
which is designed to amortize the cost of the assets over their
estimated useful lives.

Ceiling test

As of January 1, 2003, the Company adopted a new accounting standard on
impairment recognition for oil and gas assets. As permitted under the
standard, the Company tests impairment against undiscounted future net
revenues from proven reserves using expected future product prices and
costs. Impairment is recognized when the carrying amount is greater than
the undiscounted future net revenues, at which time assets are written
down to the fair value of proved and probable reserves plus the cost of
unproved properties, net of impairment allowances. Fair value is
determined using expected future product prices and costs, and amounts
are discounted using a risk free interest rate.

Goodwill

Goodwill, at the time of acquisition, represents the excess of the
purchase price of a business over the fair value of net assets acquired;
thereafter, goodwill is assessed for impairment at least annually. If
the fair value of the business is less than the book value, a second
test is performed to determine the amount of the impairment. The amount
of the impairment is determined by deducting the fair value of the
business' tangible assets and liabilities from the fair value of the
business to determine the implied fair value of goodwill and comparing
that amount to the book value of goodwill. Any excess of the book value
of goodwill over the implied fair value is the impairment amount and
will be charged to income in the period of the impairment.

Joint interest operations

A portion of the Company's petroleum and natural gas activities are
conducted jointly with others. These consolidated financial statements
reflect only the Company's proportionate interest in such activities.

Revenue recognition

Revenue form the sale of petroleum and natural gas is recognized during
the month when title passes.

Transportation costs

Effective January 1, 2004, and consistent with the adoption of CICA
Handbook Section 1100 "Generally Accepted Accounting Principles,"
transportation costs are presented as an expense in the consolidated
statements of income and retained earnings. Previously these amounts
were netted against revenue. Prior periods have been reclassified to
conform to the presentation adopted in 2004.

Per share amounts

Basic per share amounts are computed by dividing earnings by the
weighted average number of common shares outstanding for the period. The
treasury stock method is used to determine the diluted per share
amounts. Under this method, the diluted weighted average number of
shares is calculated assuming the proceeds that arise from the exercise
of outstanding, in the money options are used to purchase common shares
of the Company at their average market price for the period.

Stock-based compensation

The Company has a stock-based compensation plan, which is described in
Note 7. As of January 1, 2003, the Company adopted a new accounting
standard on stock-based compensation requiring the Company to adopt the
fair value method of accounting for stock options. Stock-based
compensation expense is recorded for all options granted on or after
January 1, 2003, with a corresponding increase recorded to contributed
surplus. No compensation expense is recorded for stock options awarded
and outstanding prior to adoption of the new accounting standard. The
fair value of options granted are estimated at the date of grant using
the Black-Scholes valuation model. Upon the exercise of stock options,
consideration paid by employees or directors together with the amount
previously recognized in contributed surplus is recorded as an increase
to share capital.

Flow-through shares

A portion of the Company's exploration and development activities is
financed through proceeds received from the issue of flow through
shares. Under the terms of the flow through share issues, the tax
attributes of the related expenditures are renounced to the share
subscribers. To recognize the foregone tax benefits to the Company, the
carrying value of the shares issued is reduced by the tax effect of the
tax benefits renounced to subscribers. The tax effect of the
renouncement is recorded when the renouncements related to the
corresponding exploration and development expenditures are filed.

Income taxes

The liability method is used in accounting for income taxes. Under this
method, future tax assets and liabilities are determined based on
differences between the financial reporting and tax bases of assets and
liabilities, and measured using the substantively enacted tax rates and
laws that will be in effect when the differences are expected to
reverse. The effect on future tax assets and liabilities of a change in
tax rates is recognized in income in the period in which the change
occurs.

Financial instruments

Effective January 1, 2004 the Company implemented CICA Accounting
Guideline 13 "Hedging Relationships". The new standard requires the
identification, designation and documentation of each hedging
relationship as well as an assessment of the effectiveness of the
hedging relationship for the purposes of applying hedge accounting. The
adoption of the guideline had no impact on the Company's financial
position or results of operations.

Comparative amounts

Certain comparative amounts have been reclassified to conform to the
presentation adopted for the current period.

3. Change in Accounting Policy Required by a Change in GAAP

Effective January 1, 2004, the Company adopted the new Canadian
accounting standard for asset retirement obligations. The new standard
requires the Company to record the fair value of an asset retirement
obligation as a liability in the period in which it incurs a legal
obligation associated with the retirement of tangible long-lived assets
that result from the acquisition, construction, development, and/or
normal use of the assets. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset and
depleted and depreciated using a unit of production method over
estimated gross proved reserves. Subsequent to the initial measurement
of the asset retirement obligations, the obligations are adjusted at the
end of each period to reflect the passage of time (accretion) and
changes in the estimated future cash flows underlying the obligation.

The effect of this change in accounting policy has been recorded
retroactively with restatement of prior periods. The effect of the
adoption is presented below as increases (decreases):


As at
Balance sheet ($000s) December 31, 2003
------------------------------------------------------------------------
Asset retirement costs included in property
and equipment 8,133
Accumulated amortization on asset retirement costs
included in property and equipment 3,077
Asset retirement obligations 10,352
Accumulated future removal and site restoration liability (1,526)
Future income tax liability (1,214)
Retained earnings (2,556)
--------------

Income statement Three months ended
($000s, except per share amounts) December 31, 2003
------------------------------------------------------------------------
Accretion expense 177
Depletion and depreciation on asset retirement costs 234
Provision for estimated future removal and site
restoration liability (258)
Net income impact (125)
Basic net income per share -
Diluted net income per share ($0.01)
--------------

Income statement Year Ended
($000s, except per share amounts) December 31, 2003
------------------------------------------------------------------------
Accretion expense 702
Depletion and depreciation on asset retirement costs 665
Provision for estimated future removal and site
restoration liability (663)
Net income impact (489)
Basic net income per share ($0.02)
Diluted net income per share ($0.02)
--------------


The Company's asset retirement obligations result from net ownership
interests in petroleum and natural gas assets including well sites,
gathering systems and processing facilities. The Company estimates the
total undiscounted amount of cash flows required to settle its asset
retirement obligations to be approximately $30 million which will be
incurred between 2005 and 2034. The majority of the costs will be
incurred between 2010 and 2034. A credit-adjusted risk-free rate of 8.5
percent and an inflation rate of 1.5 percent were used to calculate the
fair value of the asset retirement obligations. A reconciliation of the
asset retirement obligations is provided below:



Asset retirement obligations
Three months ended Years ended
December 31 December 31
($000s) 2004 2003 2004 2003
------------------------------------------------------------------------
Balance, beginning of period $ 12,583 $ 9,918 $ 10,352 $ 8,258
Liabilities incurred in the
period 621 381 2,271 1,516
Liabilities settled in the
period (49) (124) (159) (124)
Accretion expense 262 177 953 702
----------------------------------------
Balance, end of period $ 13,417 $10,352 $ 13,417 $ 10,352
----------------------------------------
----------------------------------------


4. Business Combination

On April 30, 2004, the Company acquired all of the issued and
outstanding common shares of Impact Energy Inc. ("Impact") on the basis
of 0.22222 common shares of Thunder for each common share of Impact. The
value per common share issued was calculated as the average Thunder
closing share price five days before and five days after the
announcement of the acquisition. Thunder issued 18,100,317 common shares
as consideration and incurred $1.1 million in transaction costs.
Subsequent to the date of acquisition, the preliminary allocation of the
purchase price was adjusted to reflect Thunder's current understanding
of fair values as at the date of acquisition. This transaction was
accounted for by the purchase method, based on fair values as follows:



Net assets acquired ($000s)
------------------------------------------------------------------------
Current assets, including cash of $14 $ 2,692
Property and equipment 120,727
Goodwill 45,448
Current liabilities (8,912)
Asset retirement obligations (778)
Future income tax liability (22,226)
--------------
$ 136,951
--------------
--------------

Value of common shares of Thunder issued $ 135,835
Transaction costs 1,116
--------------
Total consideration $ 136,951
--------------
--------------



5. Property and Equipment
2004
Accumulated
depletion and Net book
($000s) Cost depreciation value
------------------------------------------------------------------------
Petroleum and natural gas properties 379,490 80,128 299,362
Gas plants and related facilities 130,319 24,540 105,779
Office equipment 1,336 419 917
Assets under capital lease 248 224 24
---------------------------------
511,393 105,311 406,082
---------------------------------
---------------------------------

2003
Accumulated
depletion and Net book
($000s) Cost depreciation value
------------------------------------------------------------------------
Petroleum and natural gas properties 214,199 52,417 161,782
Gas plants and related facilities 80,628 17,065 63,563
Office equipment 834 397 437
Assets under capital lease 249 122 127
---------------------------------
295,910 70,001 225,909
---------------------------------
---------------------------------


At December 31, 2004, costs of $46,288,400 (2003 - $9,884,600) related
to unproven properties including, costs associated with coal bed methane
pilot projects, have been excluded from the depletion calculation.

Thunder performed a ceiling test calculation at December 31, 2004 to
assess the recoverable value of its petroleum and natural gas interests.
The oil and gas future prices are based on January 1, 2005 benchmark
reference prices and adjusted for commodity price differentials specific
to Thunder. Based on these assumptions, there was no impairment at
December 31, 2004. The following table summarizes the benchmark
reference prices used in the ceiling test calculation:


Edmonton Light
Crude Oil Henry Hub
WTI Oil 40 degree Gas Price AECO Natural Gas
Year ($US/bbl) API ($Cdn/bbl) ($US/mmbtu) Price ($Cdn/mmbtu)
------------------------------------------------------------------------
2005 42.00 50.25 6.20 6.60
2006 40.00 47.75 6.00 6.35
2007 38.00 43.25 5.75 6.15
2008 36.00 40.75 5.50 6.00
2009 34.00 39.50 5.50 6.00
Escalate 2.0% per 2.0% per 2.0% per 2.0% per
thereafter year year year year
------------------------------------------------------------------------


6. Revolving Demand Loan

The Company has a $130 million credit facility consisting of a revolving
demand loan with a syndicate of Schedule One Canadian chartered banks
that bears interest at the bank's prime rate. The Company has pledged
all of its assets as collateral for loans under the facility.

At December 31, 2004, the effective interest rate on the debt
outstanding was 3.9% (2003 - 4.1%). Interest paid during the years ended
December 31, 2004 and 2003 approximates interest expense in each year.

While the credit facility is demand in nature, the bank has stated that
it is not its intention to call for repayment before December 31, 2005
provided there is no adverse change in the financial position of the
Company.

7. Share Capital

Authorized

Unlimited number of voting common shares with no par value

Unlimited number of non-voting preferred shares issuable in series



Issued

Number
Common shares of shares $ Thousands
------------------------------------------------------------------------
Balance December 31, 2003 31,562,062 41,081
Issued for cash on exercise of stock options 224,968 393
-------------------------
Balance March 31, 2004 31,787,030 41,474
Issued for cash on exercise of stock options 354,133 1,468
Issued on Impact acquisition (Note 4) 18,100,317 135,835
Share issue costs, net of tax of $68 - (101)
-------------------------
Balance June 30, 2004 50,241,480 178,676
Issued for cash on exercise of stock options 86,500 179
-------------------------
Balance September 30, 2004 50,327,980 178,855
Issued for cash on exercise of stock options 335,001 1,051
Flow-through shares issued for cash 1,000,000 10,000
Share issue costs, net of tax of $212 - (333)
-------------------------
Balance December 31, 2004 51,662,981 189,573
-------------------------
-------------------------


Stock-based Compensation

The Company has established a stock option plan whereby options may be
granted to the Company's directors, officers and employees for up to
4,598,000 common shares. The exercise price of each option equals the
market price of the Company's stock on the date of the grant. An
option's maximum term is five years and the options vest equally over
three years beginning at the date the option is granted. The following
is a continuity of stock options outstanding for which shares have been
reserved:



Number of Weighted average
Stock-based compensation stock options exercise price
------------------------------------------------------------------------
Balance December 31, 2003 2,873,498 $ 3.57
Exercised (224,968) 1.83
Granted 7,500 8.39
----------------------------------
Balance March 31, 2004 2,656,030 3.73
Exercised (354,133) 4.07
Granted 2,320,000 7.89
Cancelled (25,000) 6.86
----------------------------------
Balance June 30, 2004 4,596,897 $ 5.78
Exercised (86,500) 2.25
Granted 235,000 7.00
Cancelled (58,333) 7.66
----------------------------------
Balance September 30, 2004 4,687,064 $ 5.89
Exercised (335,001) 2.72
Granted 242,500 7.24
Cancelled (240,833) 7.57
----------------------------------
Balance December 31, 2004 4,353,730 $ 6.11
----------------------------------
----------------------------------


As at March 11, 2005, there were 51,714,182 common shares and stock
options to acquire an aggregate of 4,170,029 common shares outstanding.
As a result of the arrangement with Impact Energy Inc., there were
18,100,317 common shares issued. In December 2004, the Company issued
1,000,000 flow-through shares at $10 per share. The tax credits
associated with expenditures to be funded by this offering will be
renounced under the look-back rule in 2005 when the expenditures will be
incurred; therefore, no future tax liability has been booked as at
December 31, 2004.

The following summarizes information about stock options outstanding at
December 31, 2004:



Weighted- Weighted
average Weighted- average
remaining average Number exercise
Options contractual exercise exercisable price
Grant price outstanding life price (vested) (vested)
------------------------------------------------------------------------
$1.70 - $3.00 815,900 0.54 $2.30 815,900 $2.30
$3.01 - $5.00 339,498 1.66 $3.73 339,498 $3.73
$5.01 - $7.00 808,332 3.67 $5.99 220,017 $5.79
$7.01 - $8.39 2,390,000 4.40 $7.80 - -
------------------------------------------------------------------------
$1.70 - $8.39 4,353,730 3.33 $6.11 1,375,415 $3.21
------------------------------------------------------------------------
------------------------------------------------------------------------


8. Income Taxes

Income taxes recorded in the consolidated statements of income and
retained earnings differ from the tax calculated by applying the
combined Canadian corporate federal and provincial income tax rate to
income before taxes as follows:



Three months ended Years ended
December 31 December 31
($000s) 2004 2003 2004 2003
------------------------------------------------------------------------
Statutory income tax rate for
the period 38.94% 40.87% 38.94% 40.75%
Computed income tax expense $ 1,394 $ 2,120 $ 10,082 $ 13,739
Add (deduct) income tax effect
of:
Non-deductible Crown charges,
net of ARTC 1,020 586 4,749 6,261
Resource allowance (777) (339) (4,930) (6,612)
Tax rate adjustments 319 656 (1,569) (3,877)
Stock-based compensation 272 - 979 189
Other (43) 1 25 10
----------------------------------------
Future income tax 2,185 3,024 9,336 9,710
Large corporation tax 189 99 627 396
----------------------------------------
Provision for income taxes $ 2,374 $ 3,123 $ 9,963 $ 10,106
----------------------------------------
Effective tax rate 66% 60% 38% 30%
----------------------------------------
----------------------------------------


The primary components to the future net income tax liability relate to
the following:



December 31, December 31,
($000s) 2004 2003
------------------------------------------------------------------------
Property and equipment 54,779 31,937
Deferral of partnership income 19,754 6,214
Tax loss carry forwards recognized (1,441) -
Attributed Canadian royalty income (819) (619)
Asset retirement obligation (4,511) (1,680)
Share issue costs (783) (166)
Other (45) (34)
-------------------------------
Net future tax liability 66,934 35,652
-------------------------------
-------------------------------


Taxes paid approximate large corporation tax expense for each of the
years ended December 31, 2004 and 2003.

9. Risk Management

a) Credit risk

A substantial portion of the Company's accounts receivable are with oil
and gas marketing entities. The Company generally extends unsecured
credit to these companies; therefore, the collection of accounts
receivable may be affected by changes in economic or other conditions
and may accordingly impact the Company's overall credit risk. Management
believes the risk is mitigated by the size, reputation and diversified
nature of these companies to which they extend credit.

The Company has not previously experienced any material credit losses on
the collection of receivables. Of the Company's significant individual
accounts receivable at December 31, 2004, approximately 37% was owing
from one customer of which 34% represented cash calls. Subsequent to
year-end, 73% was settled (December 31, 2003 - 42% from two customers).

b) Fair value of financial instruments

The carrying amounts of financial instruments included in the balance
sheet, other than the bank loan, approximate their fair value due to
their short-term maturity.

The Company was party to an off-balance sheet power contract, a
derivative financial instrument, in 2004 and 2003. The contract fixes
the price of twenty-four megawatt hours ("MWh") of electricity per day
at $78.00 per MWh and runs through December 31, 2005. Operating expenses
for the year ended December 31, 2004 include costs of $206,000 (2003 -
$131,000) associated with this contract. At December 31, 2004 this
contract was out of the money by $320,000. This value is based upon the
fair market value of the contract at December 31, 2004 and represents
the amount the Company would be required to pay to terminate the
contract. This instrument has no book value recorded in the consolidated
financial statements.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Thunder Energy Inc.
    Douglas A. Dafoe
    President & C.E.O.
    (403) 294-1635
    (403) 232-1317 (FAX)
    Website: www.thunderenergy.com